The invention relates to power systems and methods and, more particularly, to power systems and methods employing generators.
Power distribution systems for facilities may serve critical, life safety and other types of loads that require high availability. A typical power distribution system for such a facility, therefore, may include an auxiliary generator, such as a diesel-powered motor-generator set, which may supply power to these loads when a primary power source, such as a utility source, fails. Such a generator may also be used for distributed generation (DG), wherein locally generated power is in lieu of power drawn from the utility and/or excess locally generated power is transferred to the grid.
The generators used in such applications typically are synchronous generators, and a variety of techniques are used to control synchronous generators. Isochronous speed control techniques are typically used for generators operating alone or for a generator that is serving as a “master” among a group of paralleled generators. In a typical isochronous control scheme, the energy being admitted to the prime mover of a generator is regulated to maintain generator speed in response to changes in load that would tend to cause changes in speed. An increase in load would tend to cause the generator to decelerate, but the isochronous controller acts to provide additional torque from the prime mover to maintain the generator speed. Similarly, the isochronous controller reduces torque in response to a decrease in load.
Droop speed control techniques are commonly used when a generator is acting subordinate to another generator or when the generator is providing power to a utility bus that dominantly controls voltage phase and frequency at the generator output. In a typical droop speed control technique, the generator controller uses a speed control loop that, because of the inability to change the actual speed of the generator, actually controls power delivered to the bus. To increase the power output of the generator, a speed set point of the speed control loop is increased, but the actual speed does not change because the speed is substantially fixed by the frequency of the grid to which the generator is connected. The actual speed of the generator, thus, “droops” with respect the speed set point, and the difference between the set point and the actual speed is correlated to the amount of power being delivered by the generator.
FIG. 1 illustrates a conventional DG system. A utility recloser 2 and a service entrance breaker 3 convey power from a utility source 1 to a generator bus 4. A load may be connected to the generator bus 4 by a load breaker 8. A generator 5 may be connected and disconnected to and from the generator bus 4 by a generator breaker 6. A system controller 7 monitors voltage and current upstream of the service entrance breaker 3 and voltage and current on the generator bus 4 and responsively controls the service entrance breaker 3, the generator breaker 6 and the generator 5.
During parallel generation with the utility, the recloser 2 and the service entrance and generator breakers 3, 6 are closed, such that the generator 5 operates in parallel with the utility source 1. Typically, the service entrance breaker 3 is allowed to close only after determining that the voltage, frequency and phase on the utility side of the service entrance breaker 3 and voltage, frequency and phase on the generator bus 4 agree within a predetermined tolerance, e.g., within 5%. The system controller 7 measures these quantities and may also compute additional derived quantities, such as real and reactive power flows and power factor, based on these measured quantities. This information may be used for protective and control functions, including overcurrent, undervoltage, overvoltage, underfrequency and overfrequency protection and load sharing between generators if multiple generators are operated in parallel. The system controller 7 may trip the service entrance and generator breakers 3, 6 as part of these functions.
When co-generating, the phase and frequency of the voltage on the generator bus 4 are typically controlled by the utility source 1. Accordingly, the system controller 7 operates in a mode, e.g., a droop control mode, where the controller 7 does not control frequency and phase of the generator 5. However, when the utility source 1 is lost, the phase and frequency of the generator 5 is no longer constrained by the utility source 1. Upon loss of connection to the utility source 1, the system controller 7 can change over to a mode, e.g., an isochronous control mode, that allows the generator 5 to continue operating independently.
If the loss of connection to the utility source 1 is only momentary and power is restored before the system controller 7 can detect the loss, the generator bus 4 will be live when the utility source 1 is re-connected. If the frequency and/or phase of the generator bus 4 has drifted with respect to the utility during the period of disconnection, the re-connection may be out of phase, which can cause large transient currents, voltages and torques that may cause equipment damage.
Upon loss of utility power, it is generally desirable that the generator of a DG system disconnect from the grid as soon as possible. As discussed above, the loss of utility power may be of short duration, e.g., on the order of a few cycles, as is common with operation of reclosers, and the DG system may have difficulty detecting the loss of the utility, factors that together may cause the DG system to fail to disconnect the generator before utility power is restored. If the DG generation system has failed to disconnect the generator from the utility and the locally generated voltage has shifted in phase with respect to the grid voltage when the utility power returns, return of utility power can cause serious problems, including overcurrent trips by the generator or at the utility service entrance, damage to the generator shaft couplings, generator rotor damage due to overtorque and blown utility or customer fusing. These problems may arise because generator phase lock is typically lost once the utility is separated from the generator and reclosers typically reapply power to the downstream grid without concern for phase relationships between the utility and the downstream bus.
A conventional technique for preventing these problems is described in IEEE 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems (2003). This standard describes several techniques for detecting a loss of utility, including the installation of directional overcurrent and direction power relaying, frequency relaying, rate-of-change of frequency detection and voltage monitoring at the DG site service entrance. Generally, however, the more closely the current or power flowing into or out of the DG site approaches zero or the greater the percentage of total load on the DG feeder is supported by the DG generator, the more difficult it may be to detect loss of utility power using such techniques.
A conventional technique for controlling a DG system in response to recloser or substation breaker operation involves providing a communications link between the next upstream utility recloser or substation breaker and the main service entrance breaker of the DG system. When the monitored upstream recloser or breaker opens, a signal is transmitted to the DG system, which responsively opens the service entrance breaker. Such a “transfer trip” system may be relatively expensive, typically requires installation at both utility and customer locations and may require ongoing expenses for providing communications. In addition, if utility power is lost upstream of the monitored recloser or breaker, the transfer trip typically will not occur, and the service entrance breaker will not trip, potentially leading to the out-of-phase reconnection problems described above.